1. Field of the Invention
The present invention relates to an automated method and apparatus to catch and release a plunger which reciprocates in a production tubing of a well wherein the plunger and catcher operate in conjunction with opening and closing of a flowline. The present invention additionally relates to an automated method and apparatus to catch and release a plunger which reciprocates in a production tubing having an automated chemical launcher which operates in conjunction with the catcher and releaser.
2. Prior Art
Wells that produce natural gas very often also produce liquids, such as oil or water. Natural gas and liquids flow into the wellbore due to the pressure inside the wellbore being less than the pressure in the underground reservoir. This differential pressure is often referred to as “drawdown”. If the flow rate of natural gas is high enough, the liquids are swept upward and continuously removed from the wellbore by the velocity of the natural gas. However, as the well ages, the flow rate of the natural gas will often decrease to the point where the velocity is insufficient to continuously remove these liquids from the wellbore. As the liquid “falls back”, a liquid fluid level begins to form in the wellbore. This liquid level exerts a hydrostatic pressure. As the liquid level (and the hydrostatic pressure) increase, the pressure inside the wellbore at the formation face begins to increase. Since flow from the reservoir into the wellbore is governed by the differential pressure between the reservoir and the wellbore, an increase in pressure due to this fluid column reduces the flow from the reservoir. This is referred to “liquid loading”. Once the hydrostatic pressure caused by the fluid column inside the wellbore equalizes with the pressure in the reservoir, flow from the reservoir decreases to zero. The well is then referred to as being “loaded up”.
To alleviate this “loaded up” condition, various forms of “artificial lift” exist. “Artificial lift” includes the many methods that allow a well to be produced after natural flow has ceased from a well. One such form of artificial lift is “plunger lift”. Plunger lift is a form of artificial lift whereby a “plunger” or piston is utilized to provide a solid interface between the natural gas and the fluid so as to prevent the liquid from falling back and accumulating in the reservoir. Examples of plungers are seen in McMurry (U.S. Pat. No. 2,878,754) and Fineberg (U.S. Pat. No. 4,984,969). The plunger itself comes in various sizes and designs but in general is a cylindrical metal object that has a diameter that is slightly smaller than the internal diameter of the well's production tubing. This close tolerance in diameters allows the plunger to reciprocate up and down the length of the tubing, but the tolerance is close enough that fluid that accumulates in the tubing is swept upward by the plunger. Plunger lift is a form of “intermittent” artificial lift so designated because the well is cycled through intermittent periods of being shut in and then opened up for production. These cycles of shut-in/production are controlled automatically with valves and controllers typically supplied as part of the overall plunger lift installation.
The general operation of existing plunger lift systems may be observed from FIG. 1 as follows:                1) A spring (not shown) is installed in the bottom of the production tubing (not shown) downhole below the surface 8 to cushion the fall of the plunger 12 and prevent it from falling out the bottom of the tubing (not shown).        2) Surface equipment, above a wellhead 14, is installed on the well as follows:                    a. A catcher 16 is installed onto a tubing extension 10 above the wellhead valve connection 14 to provide a hollow receptacle for the plunger 12 when it arrives at the surface. The receptacle may sometimes broadly be referred to as a lubricator—an equalizing chamber to introduce something in a pressurized system. Integral to this catcher/lubricator 16 is a manually operated “catcher” mechanism 18 which can be set to prevent the plunger 12 from falling back down the tubing. This manual catcher provides a means for the plunger to be held at the surface for subsequent retrieval by an operator. The catcher mechanism must be armed to activate by the operator and also manually reset by the operator.            b. A controller 20 is used to control actuation of various valves in the system. Most commonly, the controller 20 actuates opening and closing of a flowline valve 22 by sending a signal to a switch such as a micro pressure switch 24 connected to the flowline valve 22. The valve may be actuated by gas pressure on a diaphragm or another mechanism. This flowline valve is the mechanism by which the well is either shut in or opened to flow.            c. Commonly installed onto the catcher 16 is a plunger arrival detection switch 26 that detects the arrival of the plunger into the lubricator. Upon detection of the plunger 12, this switch 26 sends a signal to the controller 20, where this information is stored.                        3) Upon initial installation, the plunger 12 is installed in the lubricator/catcher 16 and allowed to fall by gravity to the spring at the bottom. There is enough tolerance in diameters that the plunger 12 will fall through fluid that has accumulated in the tubing.        4) The well is then shut in at the surface using the flowline valve 22 and pressure is allowed to build up in the well.        5) The surface controller 20 can be programmed to open and close the flowline valve 22 based on numerous parameters such as time or pressure. Upon reaching the set parameter, the flowline valve 22 is opened. Since pressure has built on the well, flow occurs in the direction shown by arrow 28 from the wellbore through the open flowline valve 22. The plunger 12 ascends from the bottom of the tubing, driven by the gas pressure below it. The plunger 12 travels at a high velocity and its close tolerance allows minimal fluid to slip past the plunger 12 as it travels up tubing, pushing a column of fluid ahead of it. The fluid is removed from the tubing through the flowline as the plunger 12 arrives at the surface. Flow is allowed to continue until the controller 20 senses a programmed parameter (such as time or pressure) at which time the controller 20 signals the flowline valve 22 to close and the well is shut in. When the flow in the tubing decreases, gravity acting on the weight of the plunger 12 allows it to fall back down the production tubing to the spring on bottom and the cycle is repeated.        
The reciprocating plunger also serves a secondary purpose of periodically cleaning the production tubing of paraffin buildup on paraffinic oil wells.
The application of chemicals to wells is also a common, known practice. These chemicals can be applied in liquid form on a continuous basis by use of a chemical pump or can be applied in solid form by use of solid chemical formed into stable, solid “sticks”.
The nature of these chemicals, whether in liquid or solid form, can vary and includes:                Surfactants (commonly known as “soap” or “foamer”): Applied to natural gas wells to reduce the surface tension of produced water, creating a lower density “foamed” fluid. This lower density “foamed” fluid column exerts less of a hydrostatic pressure than a pure liquid fluid column. This results in several benefits to the well: 1.) The reduced hydrostatic pressure results in an increased “drawdown” on the well, resulting in an increase in the well's gas flow rate; 2.) The lower density “foamed” fluid column is more easily removed from the wellbore by the flowing gas stream.        Corrosion Inhibitors: Applied to natural gas wells and oil wells to provide a protective “film” on the walls of the well's tubulars, thereby inhibiting attack on the tubulars from corrosive wellbore fluids.        Scale Inhibitors: Applied to natural gas wells and oil wells to chemically inhibit the formation of scale products that form downhole.        Other Chemicals: Other chemicals sometimes applied to natural gas and oil wells include methanol (for the control of hydrates) and paraffin solvents/dispersants (for the control of paraffin products).        
Applying chemicals, whether in liquid or solid form, down the production tubing of a flowing natural gas well requires the flow to either be shut-in, or at minimum, to be at a rate low enough to allow the chemicals to fall down the tubing by the force of gravity. If the flow of natural gas and fluids from the well up the tubing is too great, the force of this flow would tend to sweep the chemicals out of the tubing, thereby preventing effective application of the chemicals.
It is known to apply chemicals to natural gas wells in the following manner:                A chemical injector “launcher” is installed on top of the wellhead. This launcher typically consists of a valve arrangement with a pipe chamber (“lubricator”) designed to hold solid chemical sticks. This lubricator is used to apply solid chemical sticks to the well's tubing during periods when the well is shut-in. This is a manual process requiring action by the lease operator to load the lubricator with chemical sticks and apply them to the well's tubing by opening the valve arrangement and allowing the chemical sticks to fall down the well's tubing by the force of gravity.        An improvement to the above process is an automated chemical stick launcher 30, depicted in the diagram in FIG. 2. This assembly typically consists of a lubricator 32 designed to hold several chemical sticks 34 and an automated valve mechanism 36 designed to apply one or more sticks 34 to the wellbore tubing automatically. The automated valve mechanism 36 is actuated by a controller 38 programmed to actuate the valve 36 on various pre-programmed parameters such as time or pressure. The controller communicates with a switch, such as a micro pressure switch 40 to actuate the valve mechanism 36. The controller 38 is designed to apply the sticks 34 by actuating the opening and closing of the automated valve 36, thereby allowing one or more of the chemical sticks to gravity fall down the well's tubing. There are numerous automated chemical stick launchers in use throughout the industry. In every case, the chemical launcher is in line and aligned with the production tubing at the surface of the well head.        
Currently, no mechanism currently exists to automatically catch and release a plunger. Accordingly, it would be desirable to provide an automated plunger catcher and releaser assembly.
Since plunger lift equipment and chemical stick launchers (whether manual or automatic) both require installation on top of the wellhead, it is prohibitive to use these technologies simultaneously. Accordingly, it would be desirable to provide a method and apparatus for a plunger catcher/releaser which could be installed and operate in sequence with a chemical launcher.